Subterranean treatment fluids comprising polyoxazoline compositions and methods of use in subterranean formations

ABSTRACT

The present invention relates to subterranean treatment fluids. In particular, the present invention relates to subterranean treatment fluid compositions that comprise polyoxazoline compositions and methods for using such compositions in subterranean applications. In one embodiment, the present invention provides a method of controlling shale swelling in a subterranean formation comprising introducing a treatment fluid into the subterranean formation, wherein the treatment fluid comprises a base fluid and a polyoxazoline composition. In another embodiment, the present invention provides a method of treating a portion of a subterranean formation comprising the steps of: introducing a treatment fluid that comprises a base fluid and a polyoxazoline composition; and treating a portion of the subterranean formation. Other embodiments are provided.

BACKGROUND

The present invention relates to subterranean treatment fluids. Inparticular, the present invention relates to subterranean treatmentfluid compositions that comprise polyoxazoline compositions and methodsfor using such compositions in subterranean applications.

A subterranean treatment fluid may be used in a subterranean formationin a variety of ways. For example, a treatment fluid may be used todrill a borehole in a subterranean formation, to stimulate a well borein a subterranean formation, or to clean up a well bore in asubterranean formation, as well as for numerous other purposes. As usedherein, “treatment fluid” refers to any fluid that may be used in asubterranean application in conjunction with a desired function and/orfor a desired purpose. The term “treatment fluid” does not imply anyparticular action by the fluid.

A drilling fluid (one type of treatment fluid) often used in connectionwith drilling a well bore in a subterranean formation can be any numberof fluids (gaseous or liquid) and mixtures of fluids and solids (such assolid suspensions, mixtures and emulsions of liquids, gases and solids)used in operations to drill well bores into subterranean formations.Drilling fluids are used, inter alia, to cool the drill bit, lubricatethe rotating drill pipe to prevent it from sticking to the walls of thewell bore, prevent blowouts by serving as a hydrostatic head tocounteract the sudden entrance into the well bore of high pressureformation fluids, and remove drill cuttings from the well bore.

During drilling of subterranean well bores, it is common to encounterportions of the subterranean formation that contain materials that mayreact undesirably with water, e.g., shales or clays. For convenience, asreferred to herein, the term “shale” shall be understood to include anysubterranean materials that may “swell,” or increase in volume, whenexposed to water, whether commonly referred to as shale, clay, or othersome subterranean material. Shales may be problematic during drillingoperations, inter alia, because of their tendency to become chemicallyand/or physically altered when exposed to aqueous media such asaqueous-based drilling fluids. This alteration, of which swelling is oneexample, can result in undesirable drilling conditions and undesirableinterference with the drilling fluid. For instance, the degradation ofthe shale may interfere with attempts to maintain the integrity ofdrilled cuttings traveling up the well bore until such time as thecuttings can be removed by solids control equipment located at thesurface. Degradation, or erosion, of drilled cuttings prior to theirremoval at the surface can prolong drilling time, because shaleparticles traveling up the well bore may break into smaller and smallerparticles, which increasingly exposes more of the shale's surface areato the drilling fluid, which leads to still further absorption of water,and further degradation.

Shale disintegration may also adversely impact “equivalent circulationdensity” (ECD). ECD is affected by the solids content of the drillingfluid, which usually increases if surface solids control equipmentcannot remove shale from the drilling fluid. Plastic viscosity (anindicator of size and quantity of solids) is an important parameter indetermining drilling rate. Maintenance of appropriate ECD is important,for example, in situations where a subterranean well bore is beingdrilled wherein a narrow tolerance exists between the weight of thedrilling fluid needed to control the formation pressure, and the weightof the drilling fluid that will fracture the formation. In suchcircumstances, minimizing shale degradation provides improved control ofthe density of the drilling fluid, and enhances the probability ofsuccessfully drilling a well bore.

Shale degradation may substantially decrease the stability of the wellbore, which may cause irregularities in the diameter of the well bore,e.g., the diameter of some portions of the well bore may be eithersmaller or greater than desired. In an extreme case, shale degradationmay decrease the stability of the well bore to such an extent that thewell bore will collapse, possibly in effect, inter alia, causing damageto the surrounding formation. Degradation of the shale may also, interalia, interrupt circulation of the drilling fluid, cause greaterfriction between the drill string and the well bore, or cause the drillstring to become stuck in the well bore. These and other complicationsthat may be associated with shale swelling may greatly increase costsassociated with subterranean operations.

A traditional method of inhibiting shale swelling during drilling toattempt to minimize such complications has been to use an oil-baseddrilling fluid as opposed to an aqueous-based drilling fluid. However,oil-based drilling fluids are often environmentally undesirable becausethey may be toxic to marine plants and animals. Accordingly,environmental regulations enacted by numerous countries have curtailedthe use of oil-based drilling fluids. Consequently, water-based drillingfluids are preferred because they may have a more benign effect on theenvironment than oil-based drilling fluids.

Another means to counteract the propensity of aqueous drilling fluids tointeract with reactive shales in the formation is to add ashale-inhibiting component to the aqueous drilling fluid. As referred toherein, the term “shale-inhibiting component” will be understood to meana compound that demonstrates a propensity for inhibiting the tendency ofa sample of shale to absorb water, often by adhering to the shale'ssurface and/or insertion between clay platelets. Commonly usedshale-inhibiting components are polyacrylamides. Polyacrylamideshale-inhibiting components, however, are becoming more environmentallyundesirable, especially in heavily regulated areas, because theygenerally demonstrate low biodegradability and high toxicity. Moreover,polyacrylamide shale-inhibiting components contain a toxic residualmonomer (e.g., an unreacted monomer) that is undesirable. Additionally,the degradation products of polyacrylamide shale-inhibiting componentsare not useful; consequently, usually more must be added to keep thedesired concentration at a level to achieve a desired effect (whichmeans more of the undesirable residual monomer is added to the system).Potassium chloride is another material that has been utilized as a shaleinhibitor, but it is considered to be only moderately effective atinhibiting the swelling of shale. Furthermore, potassium chloride isenvironmentally unacceptable in some areas of the world, e.g., the NorthSea and the Gulf of Mexico. Potassium chloride also is disfavored in theMiddle East, where wells may be drilled in close proximity to aquifers.Polyglycols also have been used as shale inhibitors in water-baseddrilling fluids but have not reached satisfactory inhibition levels.Partially hydrolyzed polyacrylamides also have been utilized in manyregions, but these have been found to cause formation damage andgenerally are regarded as environmentally undesirable

SUMMARY

The present invention relates to subterranean treatment fluids. Inparticular, the present invention relates to subterranean treatmentfluid compositions that comprise polyoxazoline compositions and methodsfor using such compositions in subterranean applications.

In one embodiment, the present invention provides a method ofcontrolling shale swelling in a subterranean formation comprisingintroducing a treatment fluid into the subterranean formation, whereinthe treatment fluid comprises a base fluid and a polyoxazolinecomposition.

In another embodiment, the present invention provides a method oftreating a portion of a subterranean formation comprising the steps of:introducing a treatment fluid that comprises a base fluid and apolyoxazoline composition; and treating a portion of the subterraneanformation.

In another embodiment, the present invention provides a method ofdrilling a portion of a well bore in a subterranean formation comprisingthe steps of: providing a drilling fluid that comprises a base fluid anda polyoxazoline composition; and drilling at least a portion of the wellbore in the subterranean formation.

In another embodiment, the present invention provides a method ofavoiding the loss of circulation of a treatment fluid in a subterraneanformation, comprising the step of adding to the treatment fluid apolyoxazoline composition and introducing the treatment fluid into aportion of the subterranean formation.

In another embodiment, the present invention provides a subterraneantreatment fluid comprising a base fluid and a polyoxazoline composition.

In another embodiment, the present invention provides a subterraneanfluid loss control agent for use in subterranean applications comprisinga polyoxazoline composition.

In another embodiment, the present invention provides a shale-inhibitingcomponent for use in a subterranean application comprising apolyoxazoline composition.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof exemplary embodiments, which follows.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to subterranean treatment fluids. Inparticular, the present invention relates to subterranean treatmentfluid compositions that comprise polyoxazoline compositions and methodsfor using such compositions in subterranean applications. While thecompositions and methods of the present invention are useful in avariety of subterranean applications, they may be particularly useful inhydrocarbon and water well drilling applications. Although described inan onshore environment, the benefits of the present invention also maybe appreciated in offshore wells.

The subterranean treatment fluids may be used in a variety ofsubterranean applications, such as drilling, stimulation, and completionoperations, wherein it may be desirable to control shale swelling and/orprovide fluid loss control. In certain preferred embodiments, the fluidsof the present invention are used in drilling operations. In certainembodiments, the subterranean treatment fluids of the present inventionmay vary in density in the range of from about 4 lb/gallon to about 22lb/gallon when measured at sea level. When utilized in offshoreapplications, the treatment fluids may have a density in the range offrom about 6 lb/gallon to about 20 lb/gallon.

The subterranean treatment fluids of the present invention comprise abase fluid and a polyoxazoline composition. Other additives suitable foruse in subterranean operations also may be added to these compositionsif desired.

The base fluids utilized in the subterranean treatment fluids of thepresent invention may be aqueous-based or nonaqueous-based, or mixturesthereof. Where the base fluid is aqueous-based, the water utilized canbe fresh water, saltwater (e.g., water containing one or more saltsdissolved therein), brine (e.g., saturated saltwater), or seawater.Generally, the water can be from any source, provided that it does notcontain an excess of compounds that may adversely affect othercomponents in the treatment fluid. Potentially problematic compounds tobe mindful of will be evident to one skilled in the art with the benefitof this disclosure. Generally, the base fluid is present in an amountsufficient to form a pumpable subterranean treatment fluid. Moreparticularly, in certain embodiments, the base fluid is typicallypresent in a treatment fluid of the present invention in an amount inthe range of from about 20% to about 99.99% by volume of the treatmentfluid.

Where the base fluid is nonaqueous-based, the base fluid may compriseany number of organic fluids. Examples of suitable organic fluidsinclude, but are not limited to, mineral oils, synthetic oils, esters,and the like. Generally, these organic fluids generically are referredto herein as “oils.” Any oil in which a water solution of salts can beemulsified may be suitable for use as a base fluid in the treatmentfluids of the present invention.

The polyoxazoline compositions of the present invention may comprise apolyoxazoline, a polyoxazoline derivative, a chemically alteredpolyoxazoline, or a polyoxazoline copolymer, or a combination thereof(sometimes referred to herein collectively as “polyoxazolines”). Apolyoxazoline is made by the polymerization of an oxazoline monomer,which is described by the following, Formula I:

wherein R₁, R₂, R₃, R₄, and R₅ may be the same or different groups, andR₁, R₂, R₃, R₄, and R₅ may comprise hydrogens or a hydrocarbon grouphaving from about 1 to about 30 carbon atoms that, for example, maycomprise a linear or branched alkyl, alkenyl, aryl, alkylaryl,arylalkyl, cycloalkyl, alkyl ether, aryl ether, alkyl aryl ether,amines, esters, carboxylic acids, or amides, or a mixture thereof. R₁,R₂, R₃, R₄, and R₅ may comprise a heteroatom. In choosing a suitable R₁,R₂, R₃, R₄, and R₅, one should be mindful of potential resonance effectswith the cyclic amine group and the Lewis basic nature, as problems withthe polymerization catalysts may result. A polyoxazoline derivative, asthat term is used herein, is a polymer made from a monomer according toFormula I, but where at least one of R₁, R₂, R₃, R₄, and R₅ is not ahydrogen. For instance, in one embodiment of a polyoxazoline derivative,R₁ may be an ethyl group and R₂, R₃, R₄, and R₅ hydrogens. In anotherembodiment, R₁ may be an alkoxy group and one of R₂, R₃, R₄, and R₅ maybe an ester group while the others are hydrogens or any otherhydrocarbon group. A chemically altered polyoxazoline, as that term isused herein, refers to where a homopolymer has been made from a monomerdescribed by Formula I and then chemically altered so as to have adesired functionality, e.g., by introducing amine groups, carboxylategroups, or other functional groups into the polymer chain. Apolyoxazoline copolymer, as that term is used herein, refers to any typeof copolymer (including terpolymers, block copolymers, randomcopolymers, statistical copolymers, and the like) that comprises apolyoxazoline, a polyoxazoline derivative, a chemically alteredpolyoxazoline, and at least a second polymer or monomer, which may ormay not be a polyoxazoline or a polyoxazoline derivative. For example,one type of polyoxazoline copolymer comprises a polyoxazoline derivative(e.g., polyethyloxazoline) and polyethylene, polypropylene, and/or apolyacrylamide. An example of suitable commercially availablepolyoxazoline derivative includes poly(2-ethyl-2-oxazoline), known as“AQUAZOL,” from Polymer Chemistry Innovations, in Tucson, Ariz. Suitablepolyoxazolines preferably may have a molecular weight of from about2,000 to about 50,000; however, in other embodiments, the molecularweight may be from about 100,000 to about 700,000. Other molecularweights may be suitable, depending on the end use, as will be recognizedby one skilled in the art with the benefit of this disclosure.

As a general matter, polyoxazolines are thermally stable up totemperatures of about 380° C., which may make them useful in, forexample, well bores having relatively higher bottom hole temperatures(BHT). Also, when polyoxazolines degrade, they form degradation products(e.g., polyethylene imines) that may be useful in the subterraneanenvironment, for example, for fluid loss control. See U.S. Pat. No.5,340,860 (assigned to Halliburton Energy Services) regarding the use ofa fluid loss-reducing additive comprising a polyethylene imine in, e.g.,cement compositions, the relevant disclosure of which is incorporated byreference.

The subterranean treatment fluids of the present invention optionallymay comprise weighting agents. Such weighting agents are typically heavyminerals, such as barite, hematite, ilmenite, calcium carbonate, ironcarbonate, or the like. Where used, these weighting agents may increasethe density of a treatment fluid of the present invention sufficiently,inter alia, to offset high pressures which may be encountered duringcertain phases of the drilling operation. Where used, the weightingagents are generally present in a treatment fluid of the presentinvention in an amount in the range of from about 0% to about 40% byvolume of the base fluid.

The treatment fluids of the present invention also optionally maycomprise salts. Examples of suitable salts include soluble salts ofGroup IA and Group IIA alkali and alkaline earth metal halides, as wellas acetates, formates, nitrates, sulfates, and the like. As used herein,the terms “Group IA” and “Group IIA” will be understood to mean thoseelements depicted as belonging to either Group IA or Group IIA,respectively, as shown on the periodic table of the elements found inthe endpapers of John McMurry, Organic Chemistry (4th. ed. 2003). Incertain preferred embodiments, wherein the treatment fluids of thepresent invention comprise an aqueous-based fluid, salts such as sodiumchloride, sodium bromide, potassium chloride, sodium formate, andpotassium formate may be preferred. In certain other preferredembodiments, wherein the treatment fluids of the present inventioncomprise a nonaqueous-based fluid, calcium chloride, potassium chloride,sodium chloride, and sodium nitrate are preferred. One of ordinary skillin the art, with the benefit of this disclosure, will recognize theappropriate salt for a particular application.

Additional additives may be added to the treatment fluids of the presentinvention as deemed appropriate by one skilled in the art. Where thetreatment fluid comprises an aqueous base fluid, the treatment fluid mayfurther comprise additives such as conventional shale inhibitors,viscosifiers, filtration control agents, pH control agents, and thelike. Examples of suitable shale swelling inhibitors include, but arenot limited to, amines, polyglycols, quaternary amine salts, and thelike. Polyacrylamides, such as partially hydrolyzed polyacrylamides,also may be used as long as one is mindful of the regulations that mayapply to the application and the particular problems the polyacrylamidesmay present. An example of a suitable partially hydrolyzedpolyacrylamide is commercially available under the trade name “EZMUD®,”from Halliburton Energy Services, Inc., of Houston, Tex. An example of asuitable polyglycol is commercially available under the trade name“GEM®,” from Halliburton Energy Services, Inc., of Houston, Tex.Examples of suitable viscosifiers include clays, high molecular weightbiopolymer polysaccharides, celluloses, and the like. Examples ofsuitable clays are a sodium montmorillonite clay commercially availablefrom Halliburton Energy Services, Inc., of Houston, Tex., under thetrade name “AQUAGEL®”; and an attapulgite clay commercially availablefrom Halliburton Energy Services, Inc., of Houston, Tex., under thetrade name “ZEOGEL®.” An example of a suitable high molecular weightbiopolymer polysaccharide is commercially available under the trade name“BARAZAN®” from Halliburton Energy Services, Inc., of Houston, Tex. Anexample of a suitable hydroxyethylcellulose is commercially availablefrom Halliburton Energy Services, Inc., of Houston, Tex., under thetrade name “LIQUI-VIS®.” In certain preferred embodiments of thetreatment fluids of the present invention, BARAZAN® is used as theviscosifier when the treatment fluid comprises an aqueous-based fluid.Examples of suitable filtration control agents include starches,modified starches, carboxymethylcellulose, polyanionic cellulose,polyacrylates, and the like. An example of a suitable starch iscommercially available from Halliburton Energy Services, Inc., ofHouston, Tex., under the trade name “IMPERMEX.” An example of a suitablemodified starch is commercially available from Halliburton EnergyServices, Inc., of Houston, Tex., under the trade name “FILTER-CHEK®.”An example of a suitable carboxymethylcellulose is commerciallyavailable from Halliburton Energy Services, Inc., of Houston, Tex.,under the trade name “CELLEX.” An example of a suitable polyanioniccellulose is commercially available from Halliburton Energy Services,Inc., of Houston, Tex., under the trade name “PAC.” An example of asuitable polyacrylate is commercially available from Halliburton EnergyServices, Inc., of Houston, Tex., under the trade name “POLYAC®.” Incertain preferred embodiments of the treatment fluids of the presentinvention, FILTER-CHEK® or PAC is used as the filtration control agentwhen the treatment fluid comprises an aqueous-based fluid. Examples ofsuitable pH control agents include sodium hydroxide, potassiumhydroxide, calcium hydroxide, magnesium oxide, and the like. An exampleof a suitable source of magnesium oxide is commercially available fromHalliburton Energy Services, Inc., of Houston, Tex., under the tradename “BARABUF®.” In certain preferred embodiments of the treatmentfluids of the present invention, sodium hydroxide or potassium hydroxideis used as the pH control agent when the treatment fluid comprises anaqueous-based fluid.

Where the treatment fluids of the present invention comprise anonaqueous-based fluid, the treatment fluids may further compriseadditives such as emulsifiers, viscosifiers, filtration control agents,pH control agents, and the like. Examples of suitable emulsifiersinclude polyaminated fatty acids, concentrated tall oil derivatives,blends of oxidized tall oil and polyaminated fatty acids, and the like.Examples of suitable commercially available polyaminated fatty acids arecommercially available from Halliburton Energy Services, Inc., ofHouston, Tex., under the trade names “EZMUL” and “SUPERMUL.” An exampleof a suitable commercially available concentrated tall oil derivative iscommercially available from Halliburton Energy Services, Inc., ofHouston, Tex., under the trade name “FACTANT.” Examples of suitablecommercially available blends of oxidized tall oil and polyaminatedfatty acids are commercially available from Halliburton Energy Services,Inc., of Houston, Tex., under the trade names “INVERMUL®” and “LE MUL.”Examples of suitable viscosifiers include clays, modified fatty acids,and the like. An example of a suitable clay is an organophilic claycommercially available from Halliburton Energy Services, Inc., ofHouston, Tex., under the trade name “GELTONE.” Examples of suitablemodified fatty acids are commercially available from Halliburton EnergyServices, Inc., of Houston, Tex., under the trade names “RHEMOD-L” and“TEMPERUS.” Examples of suitable filtration control agents includelignites, modified lignites, powdered resins, and the like. An exampleof a suitable commercially available lignite is commercially availablefrom Halliburton Energy Services, Inc., of Houston, Tex., under thetrade name “CARBONOX.” An example of a suitable commercially availablemodified lignite is commercially available from Halliburton EnergyServices, Inc., of Houston, Tex., under the trade name “BARANEX.” Anexample of a suitable commercially available powdered resin iscommercially available from Halliburton Energy Services, Inc., ofHouston, Tex., under the trade name “BARABLOK.” Examples of suitable pHcontrol agents include, but are not limited to, calcium hydroxide,potassium hydroxide, sodium hydroxide, and the like. In certainexemplary embodiments wherein the treatment fluids of the presentinvention comprise a nonaqueous-based fluid, calcium hydroxide is apreferred pH control agent.

While a number of preferred embodiments described herein relate todrilling fluids and compositions, it is understood that any welltreatment fluid, such as drilling, completion, and stimulation fluids,including, but not limited to, drilling muds, well cleanup fluids,workover fluids, spacer fluids, gravel pack fluids, acidizing fluids,fracturing fluids, and the like, may benefit from the addition of apolyoxazoline composition of the present invention. Furthermore, thetreatment fluids of the present invention may be used in drilling wellsin formations comprising thief zones. As referred to herein, the term“thief zones” will be understood to mean segments of a subterraneanformation which are sufficiently fractured (before or during drilling)as to potentially cause the loss of circulation of fluids out of thewell bore into such fractures. Where the treatment fluids of the presentinvention are used in formations comprising thief zones, a portion ofthe treatment fluid may flow into such thief zones to prevent furtherloss of circulation, e.g., through the degradation products of thepolyoxazoline compositions.

In one embodiment, the present invention provides a method ofcontrolling shale swelling in a subterranean formation comprisingintroducing a treatment fluid into the subterranean formation, whereinthe treatment fluid comprises a base fluid and a polyoxazolinecomposition.

In another embodiment, the present invention provides a method oftreating a portion of a subterranean formation comprising the steps of:introducing a treatment fluid that comprises a base fluid and apolyoxazoline composition; and treating a portion of the subterraneanformation.

In another embodiment, the present invention provides a method ofdrilling a portion of a well bore in a subterranean formation comprisingthe steps of: providing a drilling fluid that comprises a base fluid anda polyoxazoline composition; and drilling at least a portion of the wellbore in the subterranean formation.

In another embodiment, the present invention provides a method ofavoiding the loss of circulation of a treatment fluid in a subterraneanformation, comprising the step of adding to the treatment fluid apolyoxazoline composition and introducing the treatment fluid into aportion of the subterranean formation.

In another embodiment, the present invention provides a subterraneantreatment fluid comprising a base fluid and a polyoxazoline composition.

In another embodiment, the present invention provides a subterraneanfluid loss control agent for use in subterranean applications comprisinga polyoxazoline composition.

In another embodiment, the present invention provides a shale-inhibitingcomponent for use in a subterranean application comprising apolyoxazoline composition.

To facilitate a better understanding of the present invention, thefollowing examples of some of the preferred embodiments is given. In noway should such example be read to limit, or define, the scope of theinvention.

EXAMPLE

Polyethyloxazoline was studied as an example of the methods andcompositions of the present invention. Low molecular weightpolyethyloxazoline and high molecular weight polyethyloxazoline sampleswere obtained from Polymer Chemistry Innovations, in Tucson, Ariz. Thelow molecular weight sample had a molecular weight of about 50,000; thehigh molecular weight sample had a molecular weight of about 500,000.Standard solutions of each were made by adding the polymer to water, andthese were used to produce water-based fluids. Studies were undertakento compare the rheology (on a Fann 35 A rheometer), cuttings erosion (aweight test was used), and filtration control (a low-pressure API filterpress was used) of the polyethyloxazoline loadings and treatment fluidscontaining polyethyloxazoline relative to treatment fluids containingpolyacrylates. A Sanin area clay and a London area clay were used.Tables 1 and 3 contain the sample formulations. Fluid properties arecontained in Tables 2 and 4.

TABLE 1 Sample Formulations Sample Sample Sample Sample SampleComponents 1 2 3 4 5 Water, (bbl) 0.831 0.831 0.831 0.831 0.831 NaCl,(ppb) 90.7 90.7 90.7 90.7 90.7 Xanthan Viscosifier, 1 1 1 1 1 (ppb)Shale Stabilizer, (ppb) 4 4 4 4 4 Filtration Control Agent, 2 2 2 2 2(ppb) Low Molecular Weight 2 2 4 4 6 Polyethyloxazoline, (ppb) HighMolecular Weight 0.5 1.5 0.5 1.5 3 Polyethyloxazoline 500, (ppb) Barite,(ppb) 95.7 95.7 95.7 95.7 95.7

TABLE 2 Fluid Properties Sample Sample Sample Sample Sample FluidProperties 1 2 3 4 5 Aging Temperature, 150 150 150 150 150 (° F.) AgingConditions rolling rolling rolling rolling rolling Aging Period, (hr) 1616 16 16 16 600 rpm 30 31 30 33 37 300 rpm 20 22 22 23 26 200 rpm 17 1818 19 21 100 rpm 12 13 13 13 16 6 rpm 4 4 4 4 5 3 rpm 3 3 3 3 3 PV, (cP)10 9 8 10 11 YP, (lb/100 ft²) 10 13 14 13 15 10 sec. gel, (lb/100 ft²) 44 5 4 4 10 min. gel, (lb/100 ft²) 4 4 4 4 6 Sanin Clay Added, (ppb) 30.130.2 29.4 30.1 30.2 Sanin Clay Recovered 8.2 9.0 5.9 9.7 19.6 Dry, (ppb)Sanin Clay Hydrated 9.1 10.0 6.5 10.8 21.8 Weight (11%) AmountRecovered, (%) 30 33 22 36 72

TABLE 3 Sample Sample Sample Sample Fluid Formulations 1 2 3 4 Water,(bbl) 0.831 0.831 0.831 0.831 NaCl, (ppb) 90.7 90.7 90.7 90.7 XanthanViscosifier, (ppb) 1 1 1 1 Shale Stabilizer, (ppb) 4 4 4 4 FiltrationControl Agent, (ppb) 2 2 2 2 Polyacrylamide Shale-inhibiting 0 4 0 8Component A, (ppb) Polyacrylamide Shale-inhibiting 0 1.5 0 2 ComponentB, (ppb) Low Molecular Weight 4 0 8 0 Polyethyloxazoline, (ppb) HighMolecular Weight 1.5 0 2 0 Polyethyloxazoline, (ppb) Barite, (ppb) 95.795.7 95.7 95.7 KOH to pH 8.75 8.75 8.75 8.75

TABLE 4 Sample Sample Sample Sample Fluid Properties 1 2 3 4 AgingTemperature, (° F.) 150 150 150 150 Aging Conditions rolling rollingrolling rolling Aging Period, (hr) 16 16 16 16 600 rpm 37 51 37 71 300rpm 27 34 25 46 200 rpm 21 26 20 36 100 rpm 16 17 15 23 6 rpm 5 4 4 7 3rpm 4 3 3 5 PV, (cP) 10 17 12 25 YP, (lb/100 ft²) 17 17 13 21 10 sec.gel, (lb/100 ft²) 5 4 4 6 10 min. gel, (lb/100 ft²) 6 5 5 7 APIFiltrate, (30 min. at 70° F.) 9 8 7 7 London Clay Added, (ppb) 30.0 30.030.1 30.0 London Clay Recovered Dry, (ppb) 25.5 25.4 25.2 26.4 LondonClay Hydrated Weight 29.8 29.8 29.5 30.8 (14%) Amount Recovered, (%) 9999 98 103

These experiments indicate that polyoxazolines are effectiveshale-inhibiting and cuttings erosion components, and do not causesignificant increases in rheological measurements of the treatmentfluids they are used in at the loadings outlined herein.

Therefore, the present invention is well adapted to carry out theobjects and attain the ends and advantages mentioned as well as thosewhich are inherent therein. While the invention has been depicted anddescribed by reference to exemplary embodiments of the invention, such areference does not imply a limitation on the invention, and no suchlimitation is to be inferred. The invention is capable of considerablemodification, alternation, and equivalents in form and function, as willoccur to those ordinarily skilled in the pertinent arts and having thebenefit of this disclosure. The depicted and described embodiments ofthe invention are exemplary only, and are not exhaustive of the scope ofthe invention. Consequently, the invention is intended to be limitedonly by the spirit and scope of the appended claims, giving fullcognizance to equivalents in all respects.

1. A method of controlling shale swelling in a subterranean formationcomprising introducing a treatment fluid into the subterraneanformation, wherein the treatment fluid comprises a base fluid and apolyoxazoline composition.
 2. The method of claim 1 wherein introducingthe treatment fluid into the subterranean information involves drillingat least a portion of a well bore in the subterranean formation.
 3. Themethod of claim 1 wherein introducing the treatment fluid into thesubterranean formation involves stimulating at least a portion of thesubterranean formation.
 4. The method of claim 1 wherein introducing thetreatment fluid into the subterranean formation involves a completionoperation.
 5. The method of claim 1 wherein the treatment fluid is adrilling fluid.
 6. The method of claim 1 wherein the treatment fluid hasa density of about 4 lb/gallon to about 22 lb/gallon when measured atsea level.
 7. The method of claim 1 wherein the base fluid is anaqueous-based fluid, or a nonaqueous-based fluid, or a mixture thereof.8. The method of claim 1 wherein the base fluid is selected from thegroup consisting of fresh water, saltwater, a brine, and seawater. 9.The method of claim 1 wherein the base fluid comprises an organic fluid.10. The method of claim 1 wherein the base fluid is selected from thegroup consisting of a mineral oil, a synthetic oil, an ester, and acombination thereof.
 11. The method of claim 1 wherein the base fluid ispresent in the treatment fluid in an amount sufficient to make thetreatment fluid pumpable into the subterranean formation.
 12. The methodof claim 1 wherein the base fluid is present in the treatment fluid inan amount of from about 20% to about 99.99% by the volume of thetreatment fluid.
 13. The method of claim 1 wherein the polyoxazolinecomposition is selected from the group consisting of a polyoxazoline; apolyoxazoline derivative; a chemically altered polyoxazoline; apolyoxazoline copolymer; and a combination thereof.
 14. The method ofclaim 1 wherein the polyoxazoline composition is selected from the groupconsisting of a polyoxazoline, a polyoxazoline derivative, a chemicallyaltered polyoxazoline, and a polyoxazoline copolymer that has amolecular weight of between 2,000 and 50,000.
 15. The method of claim 1wherein the polyoxazoline composition is selected from the groupconsisting of a polyoxazoline, a polyoxazoline derivative, a chemicallyaltered polyoxazoline, and a polyoxazoline copolymer that has amolecular weight of between 100,000 and 700,000.
 16. The method of claim1 wherein the treatment fluid further comprises one of the following: aweighting agent; a salt; a shale-inhibiting component; a viscosifier; afiltration control agent; a pH control agent; an emulsifier; or acombination thereof.
 17. The method of claim 1 wherein the subterraneanformation comprises a thief zone.
 18. A method comprising the steps of:introducing a treatment fluid that comprises a base fluid and apolyoxazoline composition into a portion of a subterranean formationcomprising reactive shales; and allowing the polyoxazoline compositionto at least partially control shale swelling.
 19. The method of claim 18wherein introducing the treatment fluid into the subterraneaninformation involves drilling at least a portion of a well bore in thesubterranean formation.
 20. The method of claim 18 wherein introducingthe treatment fluid into the subterranean information involvesstimulating at least a portion of the subterranean formation.
 21. Themethod of claim 18 wherein the treatment fluid is a drilling fluid. 22.The method of claim 18 wherein the treatment fluid has a density ofabout 4 lb/gallon to about 221b/gallon when measured at sea level. 23.The method of claim 18 wherein the base fluid is an aqueous-based fluid,or a nonaqueous-based fluid, or a mixture thereof.
 24. The method ofclaim 18 wherein the base fluid is present in the treatment fluid in anamount of from about 20% to about 99.99% by the volume of the treatmentfluid.
 25. The method of claim 18 wherein the polyoxazoline compositionis selected from the group consisting of a polyoxazoline; apolyoxazoline derivative; a chemically altered polyoxazoline; apolyoxazoline copolymer; and a combination thereof.
 26. The method ofclaim 18 wherein the treatment fluid further comprises one of thefollowing: a weighting agent; a salt; a shale-inhibiting component; aviscosifier; a filtration control agent; a pH control agent; anemulsifier; or a combination thereof.
 27. A method of drillingcomprising the steps of: providing a drilling fluid that comprises abase fluid and a polyoxazoline composition; drilling at least a portionof a well bore in a subterranean formation comprising reactive shales;and allowing the polyoxazoline composition to at least partially controlshale swelling.
 28. The method of claim 27 wherein the well bore is awater well or a hydrocarbon well.
 29. The method of claim 27 wherein thewell bore is located offshore.
 30. The method of claim 27 wherein thedrilling fluid has a density of about 4 lb/gallon to about 22 lb/gallonwhen measured at sea level.
 31. The method of claim 27 wherein the basefluid is an aqueous-based fluid, or a nonaqueous-based fluid, or amixture thereof.
 32. The method of claim 27 wherein the base fluid ispresent in the drilling fluid in an amount of from about 20% to about99.99% by the volume of the treatment fluid.
 33. The method of claim 27wherein the polyoxazoline composition is selected from the groupconsisting of a polyoxazoline; a polyoxazoline derivative; a chemicallyaltered polyoxazoline; a polyoxazoline copolymer; and a combinationthereof.
 34. The method of claim 27 wherein the drilling fluid furthercomprises one of the following: a weighting agent; a salt; ashale-inhibiting component; a viscosifier; a filtration control agent; apH control agent; an emulsifier; or a combination thereof.